In drilling a borehole in the earth, such as for the recovery of hydrocarbons or for other applications, it is conventional practice to connect a drill bit on the lower end of an assembly of drill pipe sections which are connected end-to-end so as to form a "drill string." The drill string is rotated by apparatus that is positioned on a drilling platform located at the surface of the borehole. Such apparatus turns the bit and advances it downward, causing the bit to cut through the formation material by either abrasion, fracturing, or shearing action, or through a combination of all cutting methods. While the bit rotates, drilling fluid is pumped through the drill string and directed out of the drill bit through nozzles that are positioned in the bit face. The drilling fluid cools the bit and flushes cuttings away from the cutting structure and face of the bit. The drilling fluid and cuttings are forced from the bottom of the borehole to the surface through the annulus that is formed between the drill string and the borehole.
Many different types of drill bits with different rock removal mechanisms have been developed and found useful in drilling such boreholes. Such bits include diamond impregnated bits, milled tooth bits, tungsten carbide insert ("TCI") bits, polycrystalline diamond compacts ("PDC") bits, and natural diamond bits. The selection of the appropriate bit and cutting structure for a given application depends upon many factors. One of the most important of these factors is the type of formation that is to be drilled, and more particularly, the hardness of the formation that will be encountered. Another important consideration is the range of hardnesses that will be encountered when drilling through layers of differing formation hardness.
Depending upon formation hardness, certain combinations of the above-described bit types and cutting structures will work more efficiently and effectively against the formation than others. For example, a milled tooth bit generally drills relatively quickly and effectively in soft formations, such as those typically encountered at shallow depths. By contrast, milled tooth bits are relatively ineffective in hard rock formations as may be encountered at greater depths. For drilling through such hard formations, roller cone bits having TCI cutting structures have proven to be very effective. For certain hard formations, fixed cutter bits having a natural diamond cutting structure provide the best combination of penetration rate and durability. In soft to hard formations, fixed cutter bits having a PDC cutting structure have been employed with varying degrees of success.
The cost of drilling a borehole is proportional to the length of time it takes to drill the borehole to the desired depth and location. The drilling time, in turn, is greatly affected by the number of times the drill bit must be changed in order to reach the targeted formation. This is because each time the bit is changed, the entire drill string, which may be miles long, must be retrieved from the borehole section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string which must be reconstructed again, section by section. As is thus obvious, this process, known as a "trip" of the drill string, requires considerable time, effort and expense. Accordingly, it is always desirable to employ drill bits that will drill faster and longer and that are usable over a wider range of differing formation hardnesses. length of time that a drill bit is kept in the hole before the drill string must be tripped and the bit changed depends upon a variety of factors. These factors include the bit's rate of penetration ("ROP"), its durability or ability to maintain a high or acceptable ROP, and its ability to achieve the objectives outlined by the drilling program (especially in directional applications).
In recent years, the PDC bit has become an industry standard for cutting formations of soft and medium hardnesses. The cutter elements used in such bits are formed of extremely hard materials, which sometimes include a layer of thermally stable polycrystalline ("TSP") material or polycrystalline diamond compacts ("PDC"). In the typical PDC bit, each cutter element or assembly comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of the bit body. A disk or tablet-shaped, hard cutting layer of polycrystalline diamond is bonded to the exposed end of the support member, which is typically formed of tungsten carbide. Although such cutter elements historically were round in cross section and included a disk shaped PDC layer forming the cutting face of the element, improvements in manufacturing techniques have made it possible to provide cutter elements having PDC layers formed in other shapes as well. A PDC bit may also include on the side of the drill bit gage pads that, among other things, result in a reduction of the amount of vibration of the drill bit through maintenance of gage diameter. A "stable" PDC bit is desirable because excess vibration of the drill bit reduces the effectiveness and ROP of the drill bit, and consequently increases costs.
A known drill bit is shown in FIG. 1. Bit 10 is a fixed cutter bit, sometimes referred to as a drag bit or PDC bit, and is adapted for drilling through formations of rock to form a borehole. Bit 10 generally includes a bit body having shank 13, and threaded connection or pin 16 for connecting bit 10 to a drill string (not shown) which is employed to rotate the bit for drilling the borehole. Bit 10 further includes a central axis 11 and a cutting structure on the face 14 of the drill bit, preferably including various PDC cutter elements 40. Also shown in FIG. 1 is a gage pad 12, the outer surface of which is at the diameter of the bit and establishes the bit's size. Thus, a 12" bit will have the gage pad at approximately 6" from the center of the bit.
As best shown in FIG. 2, the drill bit body 10 includes a face region 14 and a gage pad region 12 for the drill bit. The face region 14 includes a plurality of cutting elements 40 from a plurality of blades, shown overlapping in rotated profile. The action of cutters 40 drills the borehole while the drill bit body 10 rotates. Downwardly extending flow passages 21 have nozzles or ports 22 disposed at their lowermost ends. Bit 10 includes six such flow passages 21 and nozzles 22. The flow passages 21 are in fluid communication with central bore 17. Together, passages 21 and nozzles 22 serve to distribute drilling fluids around the cutter elements 40 for flushing formation cuttings from the bottom of the borehole and away from the cutting faces 44 of cutter elements 40 when drilling.
Gage pads 12 abut against the sidewall of the borehole during drilling. The gage pads can help maintain the size of the borehole by a rubbing action when cutters on the face of the drill bit wear slightly under gage. The gage pads 12 also help stabilize the PDC drill bit against vibration. However, one problem with conventional gage pad design is excessive wear to the gage pads 12 due to their rubbing action against the borehole wall. In hard and/or abrasive formations, and also in directional applications, a method known to have helped minimize the severity of this wear problem is the placement of wear resistant materials such as diamond enhanced inserts ("DEI") and TSP elements in the gage pad, as shown in FIG. 3.
FIG. 3 includes a drill bit body 10 having a face region 14 and a gage pad region 12 for the drill bit. Each gage pad region 12 includes a first DEI 300 located directly above a second DEI 310. DEI's resist wearing away by the rubbing action of the borehole wall because they are made of a harder and more wear resistant material than that used to construct the bit body and the gage pad. Consequently, the gage pads with DEI's and TSP's continue to maintain the bit's diameter for a longer period and enhance the bit's stabilization against vibration. However, in some applications such as in horizontal drilling or directional drilling, side cutting of the borehole wall is desirable. While this gage pad design stabilizes the drill bit, it does not cut the side borehole wall.
Side cutting is a drill bit's ability to cut the sidewall of the borehole, as contrasted to the bottom of the borehole. Good side cutting action minimizes torque generation by the gage pads and solves the problem of torque fluctuation or vibrational problems associated with current design technologies. As is appreciated by those of ordinary skill in the art, this is particularly important in directional drilling applications where a drill bit must achieve different trajectories as dictated by the wellbore's inclination or azimuth, instead of drilling straight ahead. Depending on the drilling program and the types of tools being used, a bit's efficiency in its application depends on its side cutting ability.
Attempts to increase the side cutting ability of a drill bit include designing a drill bit that cuts the borehole wall at the gage pad, rather than simply resisting wear with the gage pad. FIG. 4A illustrates a head-on view of a pair of identical gage pads 12. The rotated profile of these gage pads 12 thus appears the same as the head-on view of a single gage pad 12. Each gage pad 12 includes a plurality of cutting elements 440. Between and beyond the gage pad cutting elements 440 of each gage pad is bit body material that creates a gage pad surface 410 that extends to gage diameter 420. FIG. 4B illustrates a side view of FIG. 4A showing how the cutting elements 440 are arranged on a single gage pad.
As can be appreciated, a plurality of cutters extending to gage diameter presents a cutting surface to the wall of the borehole. Such cutters are active cutting elements in the sense that they actively cut, and do not simply rub, the sidewall of the borehole. Depending on the drilling program and the types of directional work needed, cutters 440 could be put under more challenging conditions than the cutters 14 on the bit's face. In the event of a breakage or loss of one or more of these cutting elements, little gage pad protection exists. Thus, the areas between the cutting tips of each of the cutters is filled with a hard material. This hard material forms a surface 410 at the bit diameter that attempts to maintain the bit's diameter. In the resulting design, if a gage pad cutting element breaks or becomes lost, the surface 410 of the gage pad resists wear and generally acts as a conventional gage pad. However, this design is not "aggressive" and fails to cut the borehole sidewall adequately when a significant change in the direction of the wellpath is required by the at drilling program. Because side cutting is particularly important in directional drilling and rotary steerable applications, the inability to turn quickly is particularly problematic and undesirable. Further, in demanding applications such as in medium-hard, hard, or abrasive formations the material between the cutters wears away quickly and provides inadequate gage protection.
Some increased aggressiveness of the gage cutting elements could be obtained by an increased number of similarly sized gage cutting elements along a longer gage pad. However, a longer gage pad results in a slower turning drill bit. Thus this approach is not an ideal solution to the slow turn rate problem. Further, and very significantly, a longer gage pad with more cutters tends to induce higher vibration of the drill bit during drilling because those designs increase the loading, force, and torque which, in combination with the side pushing action needed to initiate and/or maintain the wellbore's path, would cause vibrations that become detrimental to operational efficiency. Drill bit designers have attempted to correct bit vibrational problems by altering the cutter layout on the face of the drill bit and by establishing effective force balancing methods. However, such stabilization methods are not always effective in the highly specialized drilling applications appropriate for a drill bit built with the inventive features disclosed herein.
Therefore, a drill bit is needed that gives effective gage protection and enhances stabilization and borehole integrity from the gage pads. The drill bit should resist bit vibration, aggressively cut the borehole wall, and turn direction quickly as needed in for directional drilling programs. This drill bit should also be resistant to cutter loss or breakage, and should be suitable for use with a variety of cutter layouts on the face of the drill bit.